In many applications, e.g., the recovery of subterranean fluids such as oil or gas, it is useful to inject fluids into or remove fluids from a geologic formation. For example, in the recovery of oil, fluids are commonly pumped through a well to treat a formation and, thereafter, oil is recovered from the formation through the well. Typically, the development of a well includes, inter alia, drilling a wellbore, inserting a casing into the wellbore, and completing the well by cementing the casing in the wellbore and opening ports in the casing through which fluids may be injected into or removed from the formation.
In completing a well, it is desirable that a zone of a wellbore adjacent a targeted formation, such as a fluid producing formation, be isolated from other zones of the wellbore. For example, if such a targeted zone is not isolated, the cement poured into the well to hold the casing in place may flow upward though the annulus between the casing and the wellbore into the zone and interfere with fluid flow between the casing ports and the formation. Similarly, annular fluid flow between the wellbore and casing may result in reduced recovery of fluids, loss of treatment fluids, or infiltration of undesired materials into a targeted zone.
These problems have been addressed in the art through the use of isolation packers to reduce annular fluid flow into or out of the targeted zone. Packers are generally employed adjacent the zone to be isolated, e.g., above and below the zone, in the annulus between the casing and the wellbore wall. The packers may comprise cementitious layers, compression packers which expand under compression forces to fill the annulus, or inflation packers which comprise jackets that can be inflated to fill the annulus. Inflation packers have been found advantageous for many applications because they are easily and quickly deployed in vertical or non-vertical wells. Deployment of inflation packers is generally accomplished by simply pumping fluid through the casing and through an inflation valve and inflation tubing which are provided to allow and hold inflation of the jackets thereby achieving and maintaining isolation of the zone.
However, there are a number of problems associated with known inflation packers. First, a jacket when attached to the casing also includes external attachment of at least a portion of the inflation valve and tubing. Thus, as the casing is inserted or moved within the wellbore, the inflation valve or tubing may be torn off or perforated resulting in a non-operational packer as well as a possible leak in the casing. In addition, some inflation packers maintain relatively low inflation pressures thereby limiting the ability of the jackets to close off the annulus between the casing and the wellbore. Moreover, where the inflation packers are deployed in formations prone to form irregularly shaped wellbore walls, e.g., sand or shale formations, fluids may leak around the packers into or out of the targeted zone. Thus, it is desirable that an inflation packer be provided which reduces the likelihood of leakage to or from the casing or the zone to be isolated and provides increased likelihood of being operational once positioned in the wellbore.
After a zone has been isolated, ports in the casing may be opened to allow injection of fluids into or removal of fluids from the geologic formation. It is desirable that the ports may be selectively opened or closed so that the ports can be closed, for example, when the formation is not being worked or when the casing is moved within the wellbore and then opened for use. One known method for opening and closing ports is by using a sliding sleeve valve. Typical sleeve valves comprise a sleeve having circumferential seals such as 0-rings at the top and bottom edges thereof to seal against a wall of the casing. Thus, when the sleeve is positioned over a port, the sleeve substantially prevents fluid communication between an interior of the casing and the formation through the port. The port may be opened by moving the sleeve so that the sleeve is located entirely above or below the port (or, in the case of a non-vertical well, entirely to one side of the port) thereby exposing the port and allowing fluid flow.
One problem associated with known sleeve valves is the tendency of the circumferential seals to develop leaks. When the sleeve is moved from a first position wherein the port is covered by the sleeve to a second position wherein the sleeve is located entirely above or below the port, the circumferential seal passes over edges of the port. After a number of opening and closing cycles, the repeated contact between the seal and port edges may cause the seal to wear and eventually result in leakage. Additionally, the sleeves are usually repositioned by inaccurate means, i.e., by "feel" rather than by positive indicators. An additional problem associated with known sleeve valves is the inability to adjust the threshold actuation force necessary to open and close such valves. Thus, it is desirable that a sleeve valve be provided which allows ports to be opened and closed with reduced wear on the sleeve valve seals, provides positive indications as to when the valve is open and closed and allows adjustment of the threshold actuation force.